Business Segments and Organizational Overview
Continuing Operations
Xcel Energy Inc. is a public utility holding company. In 2012, Xcel Energy's
continuing operations included the activity of four utility subsidiaries that
serve electric and natural gas customers in eight states. These utility
subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities
serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North
Dakota, South Dakota, Texas and Wisconsin. Along with WYCO, a joint venture
formed with CIG to develop and lease natural gas pipelines, storage and
compression facilities, and WGI, an interstate natural gas pipeline company,
these companies comprise the continuing regulated utility operations.
Xcel Energy Inc.'s nonregulated subsidiary is Eloigne, which invests in rental
housing projects that qualify for low-income housing tax credits.
Forward-Looking Statements
Except for the historical statements contained in this report, the matters
discussed in the following discussion and analysis are forward-looking
statements that are subject to certain risks, uncertainties and
assumptions. Such forward-looking statements, including the 2013 full year EPS
guidance and assumptions, are intended to be identified in this document by the
words "anticipate," "believe," "estimate," "expect," "intend," "may,"
"objective," "outlook," "plan," "project," "possible," "potential," "should" and
similar expressions. Actual results may vary materially. Forward-looking
statements speak only as of the date they are made, and we do not undertake any
obligation to update them to reflect changes that occur after that date. Factors
that could cause actual results to differ materially include, but are not
limited to: general economic conditions, including inflation rates, monetary
fluctuations and their impact on capital expenditures and the ability of Xcel
Energy Inc. and its subsidiaries to obtain financing on favorable terms;
business conditions in the energy industry, including the risk of a slow down in
the U.S. economy or delay in growth recovery; trade, fiscal, taxation and
environmental policies in areas where Xcel Energy has a financial interest;
customer business conditions; actions of credit rating agencies; competitive
factors, including the extent and timing of the entry of additional competition
in the markets served by Xcel Energy Inc. and its subsidiaries; unusual weather;
effects of geopolitical events, including war and acts of terrorism; state,
federal and foreign legislative and regulatory initiatives that affect cost and
investment recovery, have an impact on rates or have an impact on asset
operation or ownership or impose environmental compliance conditions; structures
that affect the speed and degree to which competition enters the electric and
natural gas markets; costs and other effects of legal and administrative
proceedings, settlements, investigations and claims; actions by regulatory
bodies impacting our nuclear operations, including those affecting costs,
operations or the approval of requests pending before the NRC; financial or
regulatory accounting policies imposed by regulatory bodies; availability or
cost of capital; employee work force factors; the items described under Factors
Affecting Results of Continuing Operations; and the other risk factors listed
from time to time by Xcel Energy Inc. in reports filed with the SEC, including
"Risk Factors" in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01
hereto.
Management's Strategic Plans
Xcel Energy's corporate strategy focuses on three core objectives:
· Obtain stakeholder alignment;
· Invest in our regulated utility businesses; and
· Earn a fair return on our utility investments.
Achievement of these strategic plans is designed to provide our investors with
an attractive total return and our customers with clean, safe, reliable energy
at a reasonable price. Below is a discussion of our three primary objectives and
how they support our overall strategy.
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Obtain stakeholder alignment
Successful execution of our strategy begins with obtaining stakeholder support
for long-term decisions and for large investment initiatives, prior to taking
action. To avoid excessive risk, it is critical that Xcel Energy reduce
regulatory and legislative uncertainty before making long-term critical
decisions or large capital investments. We believe stakeholder alignment is
achieved by:
· Delivering operational excellence related to reliability outage performance
and customer satisfaction;
· Proactively taking actions to ensure public and employee safety related to our
power plants, natural gas pipelines, and our transmission and distribution
system;
· Pursuing environmental leadership by reducing emissions, and expanding
renewable energy in a cost-effective manner; and
· Creating value for our customers by modernizing our infrastructure and
reducing our environmental impact at a reasonable cost, while providing customers with choices like DSM, conservation and renewable energy programs.
Invest in our utility business
After obtaining stakeholder support, the next phase of our strategy is to invest
in our regulated utility businesses. Xcel Energy projects that it will invest
approximately $13 billion in its utility businesses from 2013 through 2017. Our
capital investment plan is intended to modernize our infrastructure, improve
system reliability, reduce our impact on the environment, expand the amount of
renewable energy available to our customers and meet customer demand. We work
hard to make sure these investments provide value to our customers by selecting
cost effective projects and striving to complete these projects on time, safely
and within established budgets. As a result of these investments, Xcel Energy
projects that the rate base, or the amount on which Xcel Energy earns a return,
will grow at a compounded average annual rate of approximately 6 percent through
2014 and approximately 4 to 5 percent through 2017.
Earn a fair return on our utility investment
The third phase of our strategy is to earn a fair return on our utility
investments. Xcel Energy's regulatory strategy is based on filing reasonable
base rate requests designed to provide recovery of costs necessary to operate
our business and to earn a reasonable return on investment, along with obtaining
regulatory approval for rate riders and DSM programs. A rate rider is a
mechanism that allows for recovery of certain costs and returns on investments,
without filing a rate case.
Xcel Energy believes that our public utility commissions will provide reasonable
and timely recovery, and this is a key assumption to achieving our financial
objectives. We believe constructive regulatory outcomes over the last several
years are evidence of reasonable regulatory treatment and provide us confidence
that we are pursuing the right strategy.
Provide an attractive total return
Successful execution of the corporate strategic plan should allow Xcel Energy to
deliver an attractive total return to our shareholders. Our value proposition is
to deliver an attractive total return through a combination of earnings growth
and dividend yield.
Since 2005, our financial objectives have been to:
· Deliver a long-term annual EPS growth rate of 5 percent to 7 percent;
· Deliver an annual dividend increases of 2 percent to 4 percent; and
· Maintain senior unsecured debt credit ratings in the BBB+ to A range.
We have successfully achieved these financial objectives. Our ongoing earnings
have grown approximately 6.8 percent and our dividend has grown approximately
3.3 percent annually since 2005. In addition, our current senior unsecured debt
credit ratings for Xcel Energy and it utility subsidiaries are in the BBB+ to A
range.
We believe we are positioned to continue earnings growth of 5 percent to 7
percent and dividend growth of 2 percent to 4 percent at least through 2013 or
2014. Beyond this timeframe, we anticipate that rate base and earnings growth
could moderate. Should this occur, we anticipate having flexibility to increase
the dividend at a faster rate in the future, while ensuring a strong balance
sheet. Therefore, we believe we are positioned to continue to deliver an
attractive total return.
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Financial Review
The following discussion and analysis by management focuses on those factors
that had a material effect on Xcel Energy's financial condition, results of
operations and cash flows during the periods presented, or are expected to have
a material impact in the future. It should be read in conjunction with the
accompanying consolidated financial statements and the related notes to
consolidated financial statements.
The only common equity securities that are publicly traded are common shares of
Xcel Energy Inc. The earnings and EPS of each subsidiary discussed below do not
represent a direct legal interest in the assets and liabilities allocated to
such subsidiary but rather represent a direct interest in our assets and
liabilities as a whole. EPS by subsidiary is a financial measure not recognized
under GAAP that is calculated by dividing the net income or loss attributable to
the controlling interest of each subsidiary by the weighted average fully
diluted Xcel Energy Inc. common shares outstanding for the period. Xcel Energy's
management uses this non-GAAP financial measure to evaluate and provide details
of earnings results. Xcel Energy's management believes that this measurement is
useful to investors to evaluate the actual and projected financial performance
and contribution of our subsidiaries. This non-GAAP financial measure should not
be considered as an alternative to Xcel Energy's consolidated fully diluted EPS
determined in accordance with GAAP as an indicator of operating performance.
Results of Operations
The following table summarizes the diluted EPS for Xcel Energy:
Diluted Earnings (Loss) Per Share 2012 2011 2010
PSCo $ 0.90 $ 0.82 $ 0.86
NSP-Minnesota 0.70 0.73 0.60
SPS 0.22 0.18 0.17
NSP-Wisconsin 0.10 0.10 0.09
Equity earnings of unconsolidated subsidiaries 0.04 0.04 0.04
Regulated utility - continuing operations 1.96 1.87 1.76
Xcel Energy Inc. and other costs (0.14 ) (0.15 ) (0.14 )
Ongoing diluted earnings per share
1.82 1.72 1.62
Prescription drug tax benefit, Medicare Part D and COLI settlement 0.03
- (0.01 )
Earnings per share from continuing operations 1.85 1.72 1.61
Earnings per share from discontinued operations - - 0.01
GAAP diluted earnings per share $
1.85 $ 1.72$ 1.62
Xcel Energy's management believes that ongoing earnings provide a meaningful
comparison of earnings results and is representative of Xcel Energy's
fundamental core earnings power. Xcel Energy's management uses ongoing earnings
internally for financial planning and analysis, for reporting results to the
Board of Directors and when communicating its earnings outlook to analysts and
investors.
2012 Adjustment to GAAP Earnings
Prescription drug tax benefit - In the third quarter of 2012, Xcel Energy
implemented a tax strategy related to the allocation of funding of Xcel Energy's
retiree prescription drug plan. This strategy restored a portion of the tax
benefit associated with federal subsidies for prescription drug plans that had
been accrued since 2004 and was expensed in 2010. As a result, Xcel Energy
recognized approximately $17 million, or $0.03 per share, of income tax benefit.
2010 Adjustment to GAAP Earnings
Medicare Part D - In March 2010, the Patient Protection and Affordable Care Act
was signed into law. The law includes provisions to generate tax revenue to help
offset the cost of the new legislation. One of these provisions reduces the
deductibility of retiree health care costs to the extent of federal subsidies
received by plan sponsors that provide retiree prescription drug benefits
equivalent to Medicare Part D coverage, beginning in 2013. Xcel Energy expensed
approximately $17 million, or $0.04 per share, of previously recognized tax
benefits relating to the federal subsidies during the first quarter of 2010.
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COLI settlement - During 2007, Xcel Energy Inc. and PSCo reached a settlement
with the IRS related to a dispute associated with its COLI program. These COLI
policies were owned and managed by PSRI. As a follow on to the 2007 IRS COLI
settlement, during 2010, the IRS reached an agreement in principle of Xcel
Energy Inc.'s and PSCo's statements of account, dating back to tax year 1993.
Upon completion of this review, PSRI recorded a net non-recurring tax and
interest charge of approximately $9.4 million in 2010. The Tax Court proceedings
were dismissed in December 2010 and January 2011. Upon final cash settlement in
2011, Xcel Energy received $0.7 million and recognized a further reduction of
expense of $0.3 million. A closing agreement covering tax years 2003 through
2007 was finalized with the IRS in January 2012.
In 2010, Xcel Energy Inc., PSCo and PSRI entered into a settlement agreement
with Provident related to all claims asserted by Xcel Energy Inc., PSCo and PSRI
against Provident in a lawsuit associated with the discontinued COLI
program. Under the terms of the settlement, Xcel Energy Inc., PSCo and PSRI were
paid $25 million by Provident and Reassure America Life Insurance Company
resulting in approximately $0.05 of EPS in 2010. The $25 million proceeds were
not subject to income taxes.
Earnings Adjusted for Certain Items (Ongoing Earnings)
2012 Comparison with 2011
Xcel Energy - Overall, ongoing earnings increased $0.10 per share for
2012. Ongoing earnings increased largely due to increases in electric margins
driven by the conclusion of various rate cases, which reflect our continued
investment in our utility business and a lower ETR. Partially offsetting these
positive factors were warmer than normal winter weather, increases in
depreciation expense, O&M expenses and property taxes.
PSCo - PSCo's ongoing earnings increased $0.08 per share for 2012. The increase
is primarily due to an electric rate increase, effective May 2012, and the
impact of warmer summer weather. The increase was partially offset by decreased
wholesale revenue due to the expiration of a long-term power sales agreement
with Black Hills Corp, higher depreciation expense and O&M expenses.
NSP-Minnesota - NSP-Minnesota's 2012 ongoing earnings decreased $0.03 per
share. The decrease is primarily due to the unfavorable impact of warmer than
normal winter weather during the first quarter, electric sales decline, higher
property taxes, higher O&M expenses and depreciation expense. These decreases
were partially offset by the 2012 rate increase and a lower ETR.
SPS - SPS' ongoing earnings increased $0.04 per share for 2012. The increase is
the result of rate increases in New Mexico and Texas, effective January 2012,
partially offset by the impact of milder weather during the second half of the
year, higher depreciation expense and property taxes.
NSP-Wisconsin - NSP-Wisconsin's ongoing earnings were flat for 2012. Ongoing
earnings were positively impacted by rate increases, effective January 2012,
offset by higher O&M expenses.
2011 Comparison with 2010
Xcel Energy - Overall, ongoing earnings increased $0.10 per share for
2011. Ongoing earnings increased primarily due to higher electric margins as a
result of warmer than normal summer weather across Xcel Energy's service
territories and rate increases in various states. The higher margins were
partially offset by expected increases in O&M expenses, depreciation, interest
expense and property taxes. The increase in expenses was largely driven by
capital investment in Xcel Energy's utility business.
PSCo - PSCo earnings decreased $0.04 per share for 2011. The decrease is due to
the implementation of seasonal rates in June 2010 (seasonal rates were higher in
the summer months and lower throughout the other months of the year), higher O&M
expenses, depreciation expense and property taxes, partially offset by the
favorable impact of warmer temperatures in the summer.
NSP-Minnesota - NSP-Minnesota earnings increased $0.13 per share for 2011. The
increase is primarily due to higher interim electric rates effective in early
2011, subject to refund, in Minnesota and North Dakota, and conservation program
incentives partially offset by higher O&M expenses, depreciation expense (net of
regulatory adjustments) and property taxes.
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SPS - SPS earnings increased $0.01 per share for 2011. The increase is due to
higher electric revenues, primarily due to the Texas retail rate increase
effective in the first quarter of 2011, and warmer summer weather, partially
offset by higher O&M expenses, depreciation expense and property taxes.
NSP-Wisconsin - NSP-Wisconsin earnings increased $0.01 per share for 2011. The
increase is primarily due to higher electric rates, partially offset by higher
O&M expenses and depreciation expense.
Changes in Diluted EPS
The following table summarizes significant components contributing to the
changes in the diluted EPS compared with prior periods, which are discussed in
more detail later.
Diluted Earnings (Loss) Per Share Dec. 31
2011 GAAP and ongoing diluted earnings per share
$ 1.72
Components of change - 2012 vs. 2011
Higher electric margins
0.15
Lower effective tax rate
0.04
Lower conservation and DSM expenses (generally offset in revenues)
0.03
Higher AFUDC - Equity 0.02
Higher natural gas margins 0.01
Higher operating and maintenance expenses (0.05 )
Higher depreciation and amortization (0.04 )
Higher taxes (other than income taxes) (0.04 )
Higher interest charges (0.01 )
Other, net (including interest and premium on redemption of preferred stock) (0.01 )
2012 ongoing diluted earnings per share
1.82
Prescription drug tax benefit
0.03
2012 GAAP diluted earnings per share
$ 1.85
Diluted Earnings (Loss) Per Share Dec. 31
2010 GAAP diluted earnings per share $ 1.62
Earnings per share from discontinued operations (0.01 )
2010 diluted earnings per share from continuing operations
1.61
Medicare Part D and COLI settlement
0.01
2010 ongoing diluted earnings per share
1.62
Components of change - 2011 vs. 2010
Higher electric margins
0.44
Higher natural gas margins
0.04
Higher operating and maintenance expenses (0.11 )
Dilution from DSPP, benefit plans and the 2010 common equity issuance (0.08 )
Higher taxes (other than income taxes) (0.06 )
Higher conservation and DSM expenses (generally offset in revenues) (0.05 )
Higher depreciation and amortization (0.04 )
Other, net (including interest and premium on redemption of preferred stock) (0.04 )
2011 GAAP and ongoing diluted earnings per share $ 1.72
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The following table provides a reconciliation of ongoing and GAAP earnings and
earnings per diluted share for the years ended Dec. 31:
(Millions of Dollars) 2012 2011
2010
Ongoing earnings $ 888.3 $
840.9 $ 756.4
Prescription drug tax benefit, Medicare Part D and
COLI settlement
16.9 0.5 (4.5 )
Total continuing operations 905.2 841.4 751.9
(Loss) income from discontinued operations - (0.2 ) 3.9
GAAP earnings $ 905.2 $ 841.2 $ 755.8
Diluted Earnings (Loss) Per Share 2012 2011
2010
Ongoing diluted earnings per share (a) $ 1.82 $
1.72 $ 1.62
Prescription drug tax benefit, Medicare Part D and
COLI settlement
0.03 - (0.01 )
Earnings per share from continuing operations (a) 1.85 1.72 1.61
Earnings per share from discontinued operations - - 0.01
GAAP diluted earnings per share (a) $ 1.85 $
1.72 $ 1.62
(a) Includes the dividend requirements on preferred stock.
Continuing operations consist of the following:
· Regulated utility subsidiaries, operating in the electric and natural gas
segments; and
· Other nonregulated subsidiaries and Xcel Energy Inc.
The following table summarizes the earnings contributions of Xcel Energy's
business segments.
Contributions to Income
(Millions of Dollars) 2012 2011 2010
Regulated electric income $ 851.9 $ 789.0 $ 665.2
Regulated natural gas income 98.1 101.8 114.6
All other (a) 22.1 17.9 32.4
Xcel Energy Inc. and other costs (a) (66.9 ) (67.3 ) (60.3 )
Total income - continuing operations 905.2 841.4 751.9
(Loss) income from discontinued operations - (0.2 ) 3.9
Total net income $ 905.2 $ 841.2 $ 755.8
Contributions to Diluted Earnings (Loss) Per Share
Contributions to Diluted Earnings (Loss) Per Share 2012 2011 2010
Regulated electric $ 1.74 $ 1.62 $ 1.43
Regulated natural gas 0.20 0.21 0.24
All other (a) 0.05 0.04 0.08
Xcel Energy Inc. and other costs (a) (b) (0.14 ) (0.15 ) (0.14 )
Total earnings per share - continuing operations (b) 1.85 1.72 1.61
Discontinued operations - - 0.01
Total earnings per share - diluted (b) $ 1.85 $ 1.72 $ 1.62
(a) Not a reportable segment. Included in all other segment results in Note 16
to the consolidated financial statements.
(b) Includes the dividend requirements on preferred stock.
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Statement of Income Analysis
The following discussion summarizes the items that affected the individual
revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings - Unusually hot
summers or cold winters increase electric and natural gas sales while,
conversely, mild weather reduces electric and natural gas sales. The estimated
impact of weather on earnings is based on the number of customers, temperature
variances and the amount of natural gas or electricity the average customer
historically uses per degree of temperature. Accordingly, deviations in weather
from normal levels can affect Xcel Energy's financial performance, from both an
energy and demand perspective.
Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts
of energy required to maintain comfortable indoor temperature levels based on
each day's average temperature and humidity. Heating degree-days (HDD) is the
measure of the variation in the weather based on the extent to which the average
daily temperature falls below 65° Fahrenheit, and cooling degree-days (CDD) is
the measure of the variation in the weather based on the extent to which the
average daily temperature rises above 65° Fahrenheit. Each degree of temperature
above 65° Fahrenheit is counted as one cooling degree-day, and each degree of
temperature below 65° Fahrenheit is counted as one heating degree-day. In Xcel
Energy's more humid service territories, a THI is used in place of CDD, which
adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the
usage of Xcel Energy's residential and commercial customers. Industrial
customers are less weather sensitive.
Normal weather conditions are defined as either the 20-year or 30-year average
of actual historical weather conditions. The historical period of time used in
the calculation of normal weather differs by jurisdiction based on the time
period used by the regulator in establishing estimated volumes in the rate
setting process. To calculate the impact of weather on demand, a demand factor
is applied to the weather impact on sales as defined above to derive the amount
of demand associated with the weather impact.
The percentage increase (decrease) in normal and actual HDD, CDD and THI are
provided in the following table:
2012 vs. 2011 vs. 2012 vs. 2010 vs. 2011 vs.
Normal Normal 2011 Normal (a) 2010 (a)
HDD (15.9 ) % (1.0 ) % (14.8 ) % (4.3 ) % 3.5 %
CDD 46.1 38.1 5.7 11.9 23.4
THI 36.1 37.9 0.2 29.9 6.1
(a) Adjusted for the October 2010 sale of SPS electric distribution assets to
the city of Lubbock, Texas.
Weather - The following table summarizes the estimated impact of temperature
variations on EPS compared with sales under normal weather conditions:
2012 vs. 2011 vs. 2012 vs. 2010 vs. 2011 vs.
Normal Normal 2011 Normal 2010
Retail electric $ 0.081$ 0.080$ 0.001$ 0.040$ 0.040
Firm natural gas (0.033 ) 0.002 (0.035 ) (0.010 )
0.012
Total $ 0.048 $ 0.082 $ (0.034 ) $ 0.030 $ 0.052
In 2012, Xcel Energy refined its estimate to incorporate the impact of weather
on demand charges. As a result, the estimated weather impact on EPS for prior
periods has been adjusted for comparison purposes.
Sales Growth (Decline) - The following tables summarize Xcel Energy's sales
growth (decline) for actual and weather-normalized sales for the years ended
Dec. 31, compared with the previous year:
Dec. 31, 2012
Dec. 31, 2012 (Without Leap Day)
Weather Weather
Actual Normalized Actual Normalized
Electric residential (1.0 ) % (0.1 ) % (1.2 ) % (0.4 ) %
Electric commercial and
industrial 0.1 0.0 (0.2 ) (0.2 )
Total retail electric
sales (0.3 ) 0.0 (0.5 ) (0.3 )
Firm natural gas sales (10.6 ) (0.3 ) (11.0 ) (0.8 )
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Dec. 31, 2011
Weather
Weather Normalized
Actual Normalized Lubbock (a)
Electric residential 0.5 % (0.5 ) % 0.2 %
Electric commercial and industrial 0.3 0.0 0.7
Total retail electric sales 0.4 (0.1 ) 0.6
Firm natural gas sales 0.9 (2.5 ) N/A
(a) Adjusted for the October 2010 sale of SPS electric distribution assets to the
city of Lubbock, Texas.
Weather-normalized sales for 2013 are projected to grow approximately 0.5
percent for retail electric customers and to decline by approximately 1 percent
for retail firm natural gas customers.
Electric Revenues and Margin
Electric revenues and fuel and purchased power expenses are largely impacted by
the fluctuation in the price of natural gas, coal and uranium used in the
generation of electricity, but as a result of the design of fuel recovery
mechanisms to recover current expenses, these price fluctuations have little
impact on electric margin. The following table details the electric revenues and
margin:
(Millions of Dollars) 2012 2011 2010
Electric revenues $ 8,517 $ 8,767 $ 8,452
Electric fuel and purchased power (3,624 ) (3,992 ) (4,011 )
Electric margin
$ 4,893 $ 4,775 $ 4,441
The following tables summarize the components of the changes in electric
revenues and electric margin for the years ended Dec. 31:
Electric Revenues
(Millions of Dollars) 2012 vs.
2011
Fuel and purchased power cost recovery $ (394 )
Firm wholesale (a) (58 )
Retail sales decrease, excluding weather impact (6 )
Conservation and DSM revenue (offset by expenses) (5 )
Retail rate increases (Colorado, Texas, New Mexico, Wisconsin,
South Dakota,
North Dakota, Michigan and Minnesota) 125
Transmission revenue 44
Demand revenue 13
Conservation and DSM incentive 12
Estimated impact of weather 1
Other, net 18
Total decrease in electric revenue $
(250 )
(a) Decrease is primarily due to the expiration of a long-term wholesale power
sales agreement with Black Hills Corp., effective Jan. 1, 2012.
2012 Comparison with 2011 - Electric revenues decreased primarily due to lower
fuel and purchased power cost recovery, which is offset in operating expense.
This decrease was partially offset by the various rate increases across all of
the utility subsidiaries.
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Electric Margin
(Millions of Dollars) 2012 vs. 2011
Retail rate increases (Colorado, Texas, New Mexico, Wisconsin,
South Dakota,
North Dakota, Michigan and Minnesota)
$
125
Demand revenue
13
Transmission revenue, net of costs
13
Conservation and DSM incentive 12
Estimated impact of weather 1
Firm wholesale (a) (48 )
Retail sales decrease, excluding weather impact (6 )
Conservation and DSM revenue (offset by expenses) (5 )
Other, net
13
Total increase in electric margin $
118
(a) Decrease is primarily due to the expiration of a long-term wholesale power
sales agreement with Black Hills Corp., effective Jan. 1, 2012.
2012 Comparison to 2011 - The increase in electric margin was primarily due to
the various rate increases across all of the utility subsidiaries.
Electric Revenues
(Millions of Dollars) 2011 vs.
2010
Revenue requirements for PSCo gas generation acquisition (a) $ 124
Retail rate increases (net of revenue subject to refund) (b)
102
Transmission revenue
45
Conservation and DSM revenue (offset by expenses)
31
Fuel and purchased power cost recovery
19
Estimated impact of weather
18
Conservation and DSM incentive
14
Trading, including PSCo renewable energy credit sales (19 )
Other, net (19 )
Total increase in electric revenue $ 315
(a) The increase in revenue requirements for PSCo generation reflects the
acquisition of the Rocky Mountain and Blue Spruce natural gas facilities in
late 2010. These revenue requirements are partially offset by higher O&M
expense, depreciation expense, property taxes and financing costs.
(b) The retail rate increases include final rates in Wisconsin, Texas, Minnesota
and North Dakota.
2011 Comparison with 2010 - Electric revenues increased primarily due to the
cost recovery of the acquisition of the Rocky Mountain and Blue Spruce natural
gas facilities at PSCo and retail rate increases in Minnesota, Wisconsin, Texas,
North Dakota and Michigan.
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Electric Margin
(Millions of Dollars) 2011 vs. 2010
Revenue requirements for PSCo gas generation acquisition (a) $
124
Retail rate increases (net of revenue subject to refund) (b)
102
Conservation and DSM revenue (offset by expenses)
31
Transmission revenue, net of costs
20
Estimated impact of weather
18
Conservation and DSM incentive
14
Non-fuel riders (5 )
Other, net (including firm wholesale and deferred fuel adjustments)
30
Total increase in electric margin $ 334
(a) The increase in revenue requirements for PSCo generation reflects the
acquisition of the Rocky Mountain and Blue Spruce natural gas facilities in
late 2010. These revenue requirements are partially offset by higher O&M
expense, depreciation expense, property taxes and financing costs.
(b) The retail rate increases include final rates in Wisconsin, Texas, Minnesota
and North Dakota.
2011 Comparison to 2010 - The increase in electric margin was primarily due to
the cost recovery of the acquisition of the Rocky Mountain and Blue Spruce
natural gas facilities at PSCo and retail rate increases in Minnesota,
Wisconsin, Texas, North Dakota and Michigan.
Natural Gas Revenues and Margin
The cost of natural gas tends to vary with changing sales requirements and the
cost of natural gas purchases. However, due to the design of purchased natural
gas cost recovery mechanisms to recover current expenses for sales to retail
customers, fluctuations in the cost of natural gas have little effect on natural
gas margin. The following table details natural gas revenues and margin:
(Millions of Dollars) 2012 2011 2010
Natural gas revenues $ 1,537 $ 1,812 $
1,783
Cost of natural gas sold and transported (881 ) (1,164 ) (1,163 )
Natural gas margin
$ 656 $ 648 $ 620
The following tables summarize the components of the changes in natural gas
revenues and natural gas margin for the years ended Dec. 31:
Natural Gas Revenues
(Millions of Dollars) 2012 vs. 2011
Purchased natural gas adjustment clause recovery $ (282 )
Estimated impact of weather
(26 )
Conservation and DSM revenue (offset by expenses) (17 )
PSIA rider (Colorado), offset by expenses 29
Retail rate increase (Colorado, Wisconsin) 16
Other, net 5
Total decrease in natural gas revenues $ (275 )
2012 Comparison to 2011 - Natural gas revenues decreased primarily due to the
purchased natural gas adjustment clause recovery, which is offset in operating
expense.
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Natural Gas Margin
(Millions of Dollars) 2012 vs. 2011
PSIA rider (Colorado) offset by expenses $ 29
Retail rate increase (Colorado, Wisconsin) 16
Estimated impact of weather (26 )
Conservation and DSM revenue (offset by expenses) (17 )
Other, net 6
Total increase in natural gas margin $ 8
2012 Comparison to 2011 - Natural gas margins increased primarily due to the
PSIA rider, which is offset in operating expense.
Natural Gas Revenues
(Millions of Dollars) 2011 vs. 2010
Conservation and DSM revenue (offset by expenses) $ 13
Estimated impact of weather 9
Return on PSCo gas in storage 4
Retail rate increase (Colorado) 3
Purchased natural gas adjustment clause recovery 3
Retail sales decrease (excluding weather impact) (5 )
Conservation and DSM incentive (2 )
Other, net 4
Total increase in natural gas revenues $ 29
2011 Comparison to 2010 - Natural gas revenues increased primarily due to higher
conservation and DSM rates at NSP-Minnesota and colder weather in 2011 at PSCo
and NSP-Minnesota.
Natural Gas Margin
(Millions of Dollars) 2011 vs. 2010
Conservation and DSM revenue (offset by expenses) $ 13
Estimated impact of weather 9
Return on PSCo gas in storage 4
Retail rate increase (Colorado) 3
Retail sales decrease (excluding weather impact) (5 )
Conservation and DSM incentive (2 )
Other, net 6
Total increase in natural gas margin $ 28
2011 Comparison to 2010 - Natural gas margins increased primarily due to
increased due to higher conservation and DSM rates at NSP-Minnesota and colder
weather in 2011 at PSCo and NSP-Minnesota.
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Non-Fuel Operating Expenses and Other Items
O&M Expenses - O&M expenses increased $35.8 million, or 1.7 percent, for 2012,
compared with 2011, and by $83.0 million, or 4.0 percent for 2011, compared with
2010. The following tables summarize the changes in O&M expenses:
(Millions of Dollars) 2012 vs. 2011
Employee benefits $ 36
Pipeline system integrity costs 20
SmartGridCity 11
Prairie Island EPU 10
Plant generation costs (17 )
Bad debt expense (10 )
Labor and contract labor (2 )
Other, net (12 )
Total increase in O&M expenses $ 36
2012 Comparison to 2011 - The increase in O&M expenses for 2012 was largely
driven by the following:
· Higher employee benefits are mainly due to increased pension expenses.
· Higher pipeline system integrity costs relate to increased compliance and
inspection initiatives, which in Colorado are recovered through the pipeline
system integrity rider.
· See Item I - Business and Note 12 to the consolidated financial statements for
further discussion of SmartGridCity and Prairie Island EPU.
· Lower plant generation costs are primarily attributable to fewer plant
overhauls in 2012.
· Higher fourth quarter labor and contract labor costs are largely driven by
vegetation management and substation maintenance.
(Millions of Dollars) 2011 vs. 2010
Higher plant generation costs $ 22
Higher labor and contract labor costs 18
Higher employee benefit expense 13
Higher nuclear plant operation costs 12
Higher insurance costs 4
Other, net 14
Total increase in O&M expenses $ 83
2011 Comparison to 2010 - The increase in O&M expenses for 2011 was largely
driven by the following:
· Higher plant generation costs are attributable to incremental costs associated
with new generation placed in service and a higher level of scheduled
maintenance and overhaul work.
· Higher labor and contract labor costs are primarily due to maintenance on our
distribution facilities and the impact of annual wage increases.
· Higher employee benefit costs are largely driven by higher pension expense.
· Higher nuclear plant operation costs were largely driven by outages.
Conservation and DSM Program Expenses - Conservation and DSM program expenses
decreased $20.9 million, or 7.4 percent, for 2012, compared with 2011. The lower
expenses are primarily attributable to lower gas rider rates, as well as the
timing of recovery of electric CIP expenses at NSP-Minnesota. Conservation and
DSM program expenses are generally recovered in our major jurisdictions
concurrently through riders and base rates. Overall, the programs are designed
to encourage the operating companies and their retail customers to conserve
energy or change energy usage patterns in order to reduce peak demand on the gas
or electric system. This, in turn, reduces the need for additional plant
capacity, reduces emissions, serves to achieve other environmental goals as well
as reduces energy costs to participating customers.
Conservation and DSM program expenses increased $41.6 million, or 17.3 percent
for 2011, compared with 2010. The higher expense is primarily attributable to an
increase in the rider rates used to recover the program expenses.
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Depreciation and Amortization - Depreciation and amortization increased $35.4
million, or 4.0 percent, for 2012, compared with 2011. The increase is primarily
due to a portion of the Monticello EPU going into service in May 2011 at
NSP-Minnesota, the Jones Unit 3 going into service in June 2011 at SPS and
normal system expansion across Xcel Energy's service territories.
Depreciation and amortization expense increased $31.7 million, or 3.7 percent
for 2011, compared with 2010. This increase in depreciation expense is primarily
due to several capital projects going into service, including a portion of the
Monticello EPU going into service in May 2011, the Nobles wind project
commencing commercial operations in late 2010, the acquisition of two PSCo gas
generation facilities in December 2010, Jones Unit 3 going into service in June
2011 and normal system expansion. The increase was partially offset due to
NSP-Minnesota reducing depreciation expense by approximately $30 million in the
fourth quarter of 2011 to reflect the proposed settlement in the Minnesota
electric rate case.
Taxes (Other Than Income Taxes) - Taxes (other than income taxes) increased
$34.1 million, or 9.1 percent, for 2012, compared with 2011. The increases are
due to an increase in property taxes primarily in Minnesota. Higher property
taxes in Colorado related to the electric retail business are being deferred,
based on the multi-year rate settlement approved by the CPUC in May 2012.
Taxes (other than income taxes) increased $42.9 million, or 12.9 percent for
2011, compared with 2010. The change is primarily due to an increase in 2011 for
property taxes of approximately $29.6 million in Colorado and $8.8 million in
Minnesota.
Other Income, Net - Other income, net decreased $21.9 million for 2011, compared
with 2010, primarily due to the COLI settlement in July 2010.
AFUDC - AFUDC increased $18.8 million for 2012, compared with 2011. The increase
is primarily due to the expansion of PSCo's transmission facilities, additional
construction related to the Colorado CACJA and life extension work at the
Prairie Island nuclear generating plant.
AFUDC decreased $5.4 million, or 6.4 percent for 2011, compared with 2010. The
decrease is primarily due to lower AFUDC rates and lower average CWIP. The lower
average CWIP is attributed to Comanche Unit 3 and the Nobles wind project going
into service in 2010, offset by Monticello EPU and work at the Jones plant, as
well as SPS transmission projects in 2011.
Interest Charges - Interest charges increased $10.5 million, or 1.8 percent for
2012, compared with 2011, and $13.8 million, or 2.4 percent for 2011, compared
with 2010. The increase is due to higher long-term debt levels to fund
investment in utility operations, partially offset by lower interest rates.
Income Taxes - Income tax expense for continuing operations decreased $18.1
million for 2012, compared with 2011. The decrease in income tax expense was
primarily due to a tax benefit associated with a carryback and a tax benefit
related to the restoration of a portion of the tax benefit written off in 2010
associated with federal subsidies for prescription drug plans. As a result, Xcel
Energy recognized discrete tax benefits of approximately $14.9 million for the
carryback and $17 million for the tax benefit associated with the federal
subsidies. These were partially offset by higher pretax income in 2012. The ETR
for continuing operations was 33.2 percent for 2012, compared with 35.8 percent
for 2011. The lower ETR for 2012 was primarily due to the adjustments referenced
above. The ETR would have been 35.6 percent for 2012 without these tax benefits.
Income tax expense for continuing operations increased $31.7 million for 2011,
compared with 2010. The increase is primarily due to higher pretax income, a net
change in tax valuation allowances of $8.9 million, and the non-taxability of
the Provident settlement in 2010. These were partially offset by the 2010
write-off of the tax benefit for Medicare Part D subsidies, an adjustment
related to COLI and an increase in 2011 wind PTCs. The ETR for continuing
operations was 35.8 percent for 2011, compared with 36.7 percent for 2010. The
higher ETR for 2010 was primarily due to the Medicare Part D, COLI, and the
valuation allowance adjustments referenced above. Without these adjustments, the
ETR for continuing operations for 2010 would have been 35.1 percent. See Note 10
in the notes to consolidated financial statements for further discussion on
COLI.
Premium on Redemption of Preferred Stock - Xcel Energy Inc. redeemed all series
of its preferred stock on Oct. 31, 2011, at an aggregate purchase price of $108
million, plus accrued dividends. As such, the redemption premium of $3.3 million
and accrued dividends are reflected as reductions to earnings available to
common shareholders for 2011.
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Xcel Energy Inc. and Other Results
The following tables summarize the net income and EPS contributions of the
continuing operations of Xcel Energy Inc. and its nonregulated businesses:
Contribution to Xcel Energy's Earnings
(Millions of Dollars) 2012 2011 2010
Xcel Energy Inc. financing costs $ (71.5 ) $ (63.8 ) $ (68.7 )
Eloigne (a) 3.8 (2.9 ) 5.4
Xcel Energy Inc. taxes and other results 0.8 (0.6 ) 3.0
Total Xcel Energy Inc. and other costs -
continuing operations (66.9 ) (67.3 ) (60.3 )
Preferred dividends - (6.8 ) (4.2 )
Total Xcel Energy Inc. and other costs, available
to common shareholders $ (66.9 ) $ (74.1 ) $ (64.5 )
Contribution to Xcel Energy's Earnings per Share
(Earnings per Share) 2012 2011 2010
Xcel Energy Inc. financing costs $ (0.15 ) $ (0.13 ) $ (0.15 )
Eloigne (a) 0.01 (0.01 ) 0.01
Xcel Energy Inc. taxes and other results - - 0.01
Preferred dividends - (0.01 ) (0.01 )
Total Xcel Energy Inc. and other costs -
continuing operations $ (0.14 ) $ (0.15 ) $ (0.14 )
(a) Amounts include gains or losses associated with sales of properties held by
Eloigne.
Xcel Energy Inc.'s results include interest expense and the EPS impact of
preferred dividends, which are incurred at Xcel Energy Inc. and are not directly
assigned to individual subsidiaries.
Factors Affecting Results of Operations
Xcel Energy's utility revenues depend on customer usage, which varies with
weather conditions, general business conditions and the cost of energy
services. Various regulatory agencies approve the prices for electric and
natural gas service within their respective jurisdictions and affect Xcel
Energy's ability to recover its costs from customers. The historical and future
trends of Xcel Energy's operating results have been, and are expected to be,
affected by a number of factors, including those listed below.
General Economic Conditions
Economic conditions may have a material impact on Xcel Energy's operating
results. Management cannot predict the impact of a prolonged economic recession,
fluctuating energy prices, terrorist activity, war or the threat of
war. However, Xcel Energy could experience a material impact to its results of
operations, future growth or ability to raise capital resulting from a sustained
general slowdown in economic growth or a significant increase in interest rates.
Fuel Supply and Costs
Xcel Energy Inc.'s operating utilities have varying dependence on coal, natural
gas and uranium. Changes in commodity prices are generally recovered through
fuel recovery mechanisms and have very little impact on earnings. However,
availability of supply, the potential implementation of a carbon tax and
unanticipated changes in regulatory recovery mechanisms could impact our
operations. See Item 1 for further discussion of fuel supply and costs.
Pension Plan Costs and Assumptions
Xcel Energy has significant net pension and postretirement benefit costs that
are measured using actuarial valuations. Inherent in these valuations are key
assumptions including discount rates and expected return on plan assets. Xcel
Energy evaluates these key assumptions at least annually by analyzing current
market conditions, which include changes in interest rates and market
returns. Changes in the related net pension and postretirement benefits costs
and funding requirements may occur in the future due to changes in
assumptions. For further discussion and a sensitivity analysis on these
assumptions, see "Employee Benefits" under Critical Accounting Policies and
Estimates.
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Regulation
FERC and State Regulation - The FERC and various state regulatory commissions
regulate Xcel Energy Inc.'s utility subsidiaries. Decisions by these regulators
can significantly impact Xcel Energy's results of operations. Xcel Energy
expects to periodically file for rate changes based on changing energy market
and general economic conditions.
The electric and natural gas rates charged to customers of Xcel Energy Inc.'s
utility subsidiaries are approved by the FERC or the regulatory commissions in
the states in which they operate. The rates are designed to recover plant
investment, operating costs and an allowed return on investment. Xcel Energy
requests changes in rates for utility services through filings with the
governing commissions. Changes in operating costs can affect Xcel Energy's
financial results, depending on the timing of filing general rate cases and the
implementation of final rates. In addition to changes in operating costs, other
factors affecting rate filings are new investments, sales growth, which is
affected by overall economic conditions, conservation and DSM efforts and the
cost of capital. In addition, the regulatory commissions authorize the ROE and
capital structure in rate proceedings.
Wholesale Energy Market Regulation - Wholesale energy markets in the Midwest and
South Central U.S. are operated by MISO and SPP, respectively, to centrally
dispatch all regional electric generation and apply a regional transmission
congestion management system. NSP-Minnesota and NSP-Wisconsin are members of
MISO and SPS is a member of SPP. NSP-Minnesota, NSP-Wisconsin and SPS expect to
recover energy charges through either base rates or various recovery
mechanisms. See Note 12 to the consolidated financial statements for further
discussion.
Capital Expenditure Regulation - Xcel Energy Inc.'s utility subsidiaries make
substantial investments in plant additions to build and upgrade power plants,
and expand and maintain the reliability of the energy transmission and
distribution systems. In addition to filing for increases in base rates charged
to customers to recover the costs associated with such investments, the CPUC,
MPUC, SDPUC, NDPSC and PUCT approved proposals to recover, through a rate rider,
costs to upgrade generation plants and lower emissions, and/or increase
transmission investment cost. These non-fuel rate riders are expected to provide
significant cash flows to enable recovery of costs incurred on a timely
basis. For wholesale electric transmission services, Xcel Energy has, consistent
with FERC policy, implemented or proposed to establish formula rates for each of
the utility subsidiaries that will provide annual rate changes as transmission
investments increase in a manner similar to the rate riders.
Environmental Matters
Environmental costs include accruals for nuclear plant decommissioning and
payments for storage of spent nuclear fuel, disposal of hazardous materials and
waste, remediation of contaminated sites, monitoring of discharges to the
environment and compliance with laws and permits with respect to emissions. A
trend of greater environmental awareness and increasingly stringent regulation
may continue to cause higher operating expenses and capital expenditures for
environmental compliance.
In addition to nuclear decommissioning and spent nuclear fuel disposal expenses,
costs charged to operating expenses for environmental monitoring and disposal of
hazardous materials and waste were approximately:
· $263 million in 2012;
· $265 million in 2011; and
· $256 million in 2010.
Xcel Energy estimates an average annual expense of approximately $305 million
from 2013 through 2017 for similar costs. However, the precise timing and amount
of environmental costs, including those for site remediation and disposal of
hazardous materials, are currently unknown. Additionally, the extent to which
environmental costs will be included in and recovered through rates may
fluctuate.
Capital expenditures for environmental improvements at regulated facilities were
approximately:
· $180 million in 2012;
· $48 million in 2011; and
· $473 million in 2010.
See Item 7 - Capital Requirements for further discussion.
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Xcel Energy's operations are subject to federal and state laws and regulations
related to air emissions, water discharges, and waste management. These laws and
regulations regulate air emissions from various sources, including electrical
generating units, and impose certain monitoring and reporting requirements. Such
laws and regulations may require Xcel Energy to obtain pre-approval for the
construction or modification of certain projects that increase air emissions,
obtain and strictly comply with air permits that contain emission and
operational limitations or mandate the installation and operation of pollution
control equipment at facilities. Xcel Energy will likely be required to incur
capital expenditures in the future to comply with these requirements for
remediation plans of MGP sites and various regulations for air emissions and
water intake. Actual expenditures could be higher or lower than the estimates
presented, and the scope and timing of these expenditures cannot be fully
determined until any new or revised regulations become final.
In July 2011, the EPA issued the CSAPR, to address long-range transport of PM
and ozone by requiring reductions in SO2 and NOx from utilities located in the
eastern half of the U.S. In August 2012, the D.C. Circuit issued an opinion that
vacated the CSAPR, but required continued implementation of the CAIR pending the
EPA's development of a replacement program. In January 2013, the D.C. Circuit
denied all requests for rehearing. It is not yet known whether the D.C.
Circuit's decision will be appealed, or how the EPA might approach a replacement
rule. Therefore, it is not known what requirements may be imposed in the future.
In addition, there are emission controls, known as BART, for industrial
facilities releasing emissions that reduce visibility in certain national parks
and wilderness areas. Xcel Energy generating facilities in Minnesota and
Colorado are subject to BART requirements.
Further, generating facilities throughout the Xcel Energy territory are subject
to mercury reduction requirements at the state level. In December 2011, the EPA
adopted a regulation setting national emission limits for EGUs for mercury,
certain metals, and acid gas emissions.
See Note 13 to the consolidated financial statements for further discussion of
Xcel Energy's environmental contingencies.
Inflation
Inflation at its current level is not expected to materially affect Xcel
Energy's prices or returns to shareholders. However, potential future inflation
could result from economic conditions or the economic and monetary policies of
the U.S. Government and the Federal Reserve. This could lead to future price
increases for materials and services required to deliver electric and natural
gas services to customers. These potential cost increases could in turn lead to
increased prices to customers.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Preparation of the consolidated financial statements and related disclosures in
compliance with GAAP requires the application of accounting rules and guidance,
as well as the use of estimates. The application of these policies involves
judgments regarding future events, including the likelihood of success of
particular projects, legal and regulatory challenges and anticipated recovery of
costs. These judgments could materially impact the consolidated financial
statements and disclosures, based on varying assumptions. In addition, the
financial and operating environment also may have a significant effect on the
operation of the business and on the results reported even if the nature of the
accounting policies applied have not changed. The following is a list of
accounting policies and estimates that are most significant to the portrayal of
Xcel Energy's financial condition and results, and that require management's
most difficult, subjective or complex judgments. Each of these has a higher
likelihood of resulting in materially different reported amounts under different
conditions or using different assumptions. Each critical accounting policy has
been discussed with the Audit Committee of Xcel Energy Inc.'s Board of
Directors.
Regulatory Accounting
Xcel Energy Inc. is a holding company with rate-regulated subsidiaries that are
subject to the accounting for Regulated Operations, which provides that
rate-regulated entities account for and report assets and liabilities consistent
with the recovery of those incurred costs in rates, if the rates established are
designed to recover the costs of providing the regulated service and if the
competitive environment makes it probable that such rates will be charged and
collected. Xcel Energy's rates are derived through the ratemaking process, which
results in the recording of regulatory assets and liabilities based on the
probability of future cash flows. Regulatory assets represent incurred or
accrued costs that have been deferred because they are probable of future
recovery from customers. Regulatory liabilities represent amounts that are
expected to be refunded to customers in future rates or amounts collected in
current rates for future costs. In other businesses or industries, regulatory
assets and regulatory liabilities would generally be charged to net income or
OCI.
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As of Dec. 31, 2012 and 2011, Xcel Energy has recorded regulatory assets of $3.1
billion and $2.8 billion and regulatory liabilities of $1.2 billion and $1.4
billion, respectively. Each subsidiary is subject to regulation that varies from
jurisdiction to jurisdiction. If future recovery of costs, in any such
jurisdiction, ceases to be probable, Xcel Energy would be required to charge
these assets to current net income or OCI. There are no current or expected
proposals or changes in the regulatory environment that impact the probability
of future recovery of these assets. However, if the SEC should mandate the use
of IFRS and the lack of an accounting standard for rate-regulated entities under
IFRS could require us to charge certain regulatory assets and regulatory
liabilities to net income or OCI. See Note 15 to the consolidated financial
statements for further discussion of regulatory assets and liabilities.
Income Tax Accruals
Judgment, uncertainty, and estimates are a significant aspect of the income tax
accrual process that accounts for the effects of current and deferred income
taxes. Uncertainty associated with the application of tax statutes and
regulations and the outcomes of tax audits and appeals require that judgment and
estimates be made in the accrual process and in the calculation of the
ETR. Changes in tax laws and rates may affect recorded deferred tax assets and
liabilities and our ETR in the future.
ETRs are also highly impacted by assumptions. ETR calculations are revised every
quarter based on best available year end tax assumptions (income levels,
deductions, credits, etc.); adjusted in the following year after returns are
filed, with the tax accrual estimates being trued-up to the actual amounts
claimed on the tax returns; and further adjusted after examinations by taxing
authorities have been completed.
In accordance with the interim period reporting guidance, income tax expense for
the first three quarters in a year are based on the forecasted ETR.
Accounting for income taxes also requires that only tax benefits that meet the
more likely than not recognition threshold can be recognized or continue to be
recognized. The change in the unrecognized tax benefits needs to be reasonably
estimated based on evaluation of the nature of uncertainty, the nature of event
that could cause the change and an estimated range of reasonably possible
changes. At any period end, and as new developments occur, management will use
prudent business judgment to derecognize appropriate amounts of tax
benefits. Unrecognized tax benefits can be recognized as issues are favorably
resolved and loss exposures decline.
As disputes with the IRS and state tax authorities are resolved over time, we
may adjust our unrecognized tax benefits and interest accruals to the updated
estimates needed to satisfy tax and interest obligations for the related
issues. These adjustments may increase or decrease earnings. See Note 6 to the
consolidated financial statements for further discussion.
Employee Benefits
Xcel Energy's pension costs are based on an actuarial calculation that includes
a number of key assumptions, most notably the annual return level that pension
and postretirement health care investment assets will earn in the future and the
interest rate used to discount future pension benefit payments to a present
value obligation. In addition, the pension cost calculation uses an
asset-smoothing methodology to reduce the volatility of varying investment
performance over time. See Note 9 to the consolidated financial statements for
further discussion on the rate of return and discount rate used in the
calculation of pension costs and obligations.
Pension costs are expected to increase in 2013 and then gradually decline in the
following few years while funding requirements are expected to be flat in 2013
and decline in the following years. While investment returns exceeded the
assumed levels from 2009 through 2012, investment returns in 2008 were
significantly below the assumed levels. The pension cost calculation uses a
market-related valuation of pension assets. Xcel Energy uses a calculated value
method to determine the market-related value of the plan assets. The
market-related value is determined by adjusting the fair market value of assets
at the beginning of the year to reflect the investment gains and losses (the
difference between the actual investment return and the expected investment
return on the market-related value) during each of the previous five years at
the rate of 20 percent per year. As these differences between the actual
investment returns and the expected investment returns are incorporated into the
market-related value, the differences are recognized in pension cost over the
expected average remaining years of service for active employees.
Based on current assumptions and the recognition of past investment gains and
losses, Xcel Energy currently projects the pension costs recognized for
financial reporting purposes will increase from an expense of $127.1 million in
2012 and $81.0 million in 2011 to an expense of $158.5 million in 2013 and
$132.9 million in 2014. The expected increase in the 2013 expense is due
primarily to the continued phase in of unrecognized plan losses primarily
resulting from the market decline in 2008.
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At Dec. 31, 2012, Xcel Energy set the rate of return used to measure pension
costs at 6.88 percent, which is a 22 basis point decrease from Dec. 31,
2011. The rate of return used to measure postretirement health care costs of
7.11 percent at Dec. 31, 2012 is a 36 basis point increase from Dec. 31, 2011.
Xcel Energy set the discount rates used to value the Dec. 31, 2012 pension and
postretirement health care obligations at 4.00 percent and 4.10 percent, which
represent a 100 basis point and 90 basis point decrease from Dec. 31, 2011,
respectively. Xcel Energy uses a bond matching study as its primary basis for
determining the discount rate used to value pension and postretirement health
care obligations. The bond matching study utilizes a portfolio of high grade (Aa
or higher) bonds that matches the expected cash flows of Xcel Energy's benefit
plans in amount and duration. The effective yield on this cash flow matched bond
portfolio determines the discount rate for the individual plans. The bond
matching study is validated for reasonableness against the Citigroup Pension
Liability Discount Curve and the Citigroup Above Median Curve. At Dec. 31, 2012,
these reference points supported the selected rate. In addition to these
reference points, Xcel Energy also reviews general actuarial survey data to
assess the reasonableness of the discount rate selected.
The Pension Protection Act changed the minimum funding requirements for defined
benefit pension plans beginning in 2008. The following are the pension funding
contributions, both voluntary and required, made by Xcel Energy for 2011 through
2013:
· In January 2013, contributions of $191.5 million were made across four of Xcel
Energy's pension plans;
· In 2012, contributions of $198.1 million were made across four of Xcel
Energy's pension plans;
· In 2011, contributions of $137.3 million were made across three of Xcel
Energy's pension plans.
For future years, we anticipate contributions will be made as necessary. These
contributions are summarized in Note 9 to the consolidated financial
statements. Future year amounts are estimates and may change based on actual
market performance, changes in interest rates and any changes in governmental
regulations. Therefore, additional contributions could be required in the
future.
If Xcel Energy were to use alternative assumptions at Dec. 31, 2012, a
one-percent change would result in the following impact on 2013 pension expense:
Pension Costs
(Millions of Dollars) +1% -1%
Rate of return $ (29.2 ) $ 29.8
Discount rate (14.1 ) 17.6
Effective Dec. 31, 2012, the initial medical trend assumption was increased from
6.3 percent to 7.5 percent. The ultimate trend assumption was reduced from 5.0
percent to 4.5 percent. The period until the ultimate rate is reached is seven
years. Xcel Energy bases its medical trend assumption on the long-term cost
inflation expected in the health care market, considering the levels projected
and recommended by industry experts, as well as recent actual medical cost
increases experienced by Xcel Energy's retiree medical plan.
· Xcel Energy contributed $47.1 million and $49.0 million during 2012 and 2011,
respectively, to the postretirement health care plans.
· Xcel Energy expects to contribute approximately $21.8 million during 2013.
Xcel Energy recovers employee benefits costs in its regulated utility operations
consistent with accounting guidance with the exception of the areas noted below.
· NSP-Minnesota recognizes pension expense in all regulatory jurisdictions based
on expense as calculated using the aggregate normal cost actuarial
method. Differences between aggregate normal cost and expense as calculated by
pension accounting standards are deferred as a regulatory liability.
· Colorado, Texas, New Mexico and FERC jurisdictions allow the recovery of other
post retirement benefit costs only to the extent that recognized expense is
matched by cash contributions to an irrevocable trust. Xcel Energy has
consistently funded at a level to allow full recovery of costs in these
jurisdictions.
See Note 9 to the consolidated financial statements for further discussion.
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Nuclear Decommissioning
Xcel Energy recognizes liabilities for the expected cost of retiring tangible
long-lived assets for which a legal obligation exists. These AROs are recognized
at fair value as incurred and are capitalized as part of the cost of the related
long-lived assets. In the absence of quoted market prices, Xcel Energy estimates
the fair value of its AROs using present value techniques, in which it makes
various assumptions including estimates of the amounts and timing of future cash
flows associated with retirement activities, credit-adjusted risk free rates and
cost escalation rates. When Xcel Energy revises any assumptions used to estimate
AROs, it adjusts the carrying amount of both the ARO liability and the related
long-lived asset. Xcel Energy accretes ARO liabilities to reflect the passage of
time using the interest method.
A significant portion of Xcel Energy's AROs relates to the future
decommissioning of NSP-Minnesota's nuclear facilities. The total obligation for
nuclear decommissioning currently is expected to be funded 100 percent by the
external decommissioning trust fund. The difference between regulatory funding
(including depreciation expense less returns from the external trust fund) and
amounts recorded under current accounting guidance are deferred as a regulatory
asset. The amounts recorded for AROs related to future nuclear decommissioning
were $1,546.4 million and $1,482.7 million as of Dec. 31, 2012 and 2011,
respectively. Based on their significance, the following discussion relates
specifically to the AROs associated with nuclear decommissioning.
NSP-Minnesota obtains periodic cost studies in order to estimate the cost and
timing of planned nuclear decommissioning activities. These independent cost
studies are based on relevant information available at the time
performed. Estimates of future cash flows for extended periods of time are by
nature highly uncertain and may vary significantly from actual results.
In December 2011, NSP-Minnesota submitted to the MPUC its triennial nuclear
decommissioning filing. The filing included a decommissioning study, which
covered all expenses over the decommissioning period of the nuclear plants,
including decontamination and removal of radioactive material. The estimated
future costs were initially determined in nominal amounts (2011 dollars) prior
to escalation adjustments, then future periods' costs were escalated using
decommissioning-specific cost escalators and finally discounted using risk-free,
credit adjusted interest rates.
In November 2012, the MPUC approved NSP-Minnesota's most recent nuclear
decommissioning study which used 2011 cost data. The MPUC approved the use of a
60-year decommissioning scenario. This resulted in an approved annual accrual
for 2013 of $14.2 million for Minnesota retail customers to be offset by funds
received in 2012 of $15.3 million from the DOE settlement, which was deposited
into the external decommissioning trust fund in December 2012.
The following key assumptions have a significant effect on these estimates:
· Timing - Decommissioning cost estimates are impacted by each facility's
retirement date, as well as the expected timing of the actual decommissioning
activities. Currently, the estimated retirement dates coincide with each units
operating license with the NRC (i.e., 2030 for Monticello and 2033 and 2034
for Prairie Island's Unit 1 and 2, respectively). The estimated timing of the
decommissioning activities is based upon the DECON method, which is required
by the MPUC. By utilizing this method, which assumes prompt removal and
dismantlement, these activities are expected to begin at the end of the
license date and be completed for both facilities by 2091.
· Technology and Regulation - There is limited experience with actual
decommissioning of large nuclear facilities. Changes in technology and experience as well as changes in regulations regarding nuclear decommissioning
could cause cost estimates to change significantly. NSP-Minnesota's 2011
nuclear decommissioning filing assumed current technology and regulations.
· Escalation Rates - Escalation rates represent projected cost increases over
time due to both general inflation and increases in the cost of specific
decommissioning activities. NSP-Minnesota used an escalation rate of 3.63
percent in calculating the AROs related to nuclear decommissioning for the
remaining operational period through the radiological decommissioning
period. An escalation rate of 2.63 percent was utilized for the period of
operating costs related to interim dry cask storage of spent nuclear fuel and
site restoration.
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· Discount Rates - Changes in timing or estimated expected cash flows that
result in upward revisions to the ARO are calculated using the then-current
credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in
effect when the change occurs is used to discount the revised estimate of the
incremental expected cash flows of the retirement activity. If the change in
timing or estimated expected cash flows results in a downward revision of the
ARO, the undiscounted revised estimate of expected cash flows is discounted
using the credit-adjusted risk-free rate in effect at the date of initial
measurement and recognition of the original ARO. The estimated expected cash
flows that changed in 2012 due to the change to a 60 year decommissioning
assumption resulted in an immaterial revision to the ARO. Discount rates
ranging from approximately 4 percent and 7 percent have been used to calculate
the net present value of the expected future cash flows over time.
Significant uncertainties exist in estimating the future cost of nuclear
decommissioning including the method to be utilized, the ultimate costs to
decommission, and the planned method of disposing spent fuel. If different cost
estimates, life assumptions or cost escalation rates were utilized, the AROs
could change materially. However, changes in estimates have minimal impact on
results of operations as NSP-Minnesota expects to continue to recover all costs
in future rates.
Xcel Energy continually makes judgments and estimates related to these critical
accounting policy areas, based on an evaluation of the varying assumptions and
uncertainties for each area. The information and assumptions underlying many of
these judgments and estimates will be affected by events beyond the control of
Xcel Energy, or otherwise change over time. This may require adjustments to
recorded results to better reflect the events and updated information that
becomes available. The accompanying financial statements reflect management's
best estimates and judgments of the impact of these factors as of Dec. 31, 2012.
Derivatives, Risk Management and Market Risk
In the normal course of business, Xcel Energy Inc. and its subsidiaries are
exposed to a variety of market risks. Market risk is the potential loss that may
occur as a result of adverse changes in the market or fair value of a particular
instrument or commodity. All financial and commodity-related instruments,
including derivatives, are subject to market risk. See Note 11 to the
consolidated financial statements for further discussion of market risks
associated with derivatives.
Xcel Energy is exposed to the impact of adverse changes in price for energy and
energy-related products, which is partially mitigated by the use of commodity
derivatives. In addition to ongoing monitoring and maintaining credit policies
intended to minimize overall credit risk, when necessary, management takes steps
to mitigate changes in credit and concentration risks associated with its
derivatives and other contracts, including parental guarantees and requests of
collateral. While Xcel Energy expects that the counterparties will perform under
the contracts underlying its derivatives, the contracts expose Xcel Energy to
some credit and nonperformance risk.
Though no material non-performance risk currently exists with the counterparties
to Xcel Energy's commodity derivative contracts, distress in the financial
markets may in the future impact that risk to the extent it impacts those
counterparties. Distress in the financial markets may also impact the fair value
of the securities in the nuclear decommissioning fund and master pension trust,
as well as Xcel Energy's ability to earn a return on short-term investments of
excess cash.
Commodity Price Risk - Xcel Energy Inc.'s utility subsidiaries are exposed to
commodity price risk in their electric and natural gas operations. Commodity
price risk is managed by entering into long- and short-term physical purchase
and sales contracts for electric capacity, energy and energy-related products
and for various fuels used in generation and distribution activities. Commodity
price risk is also managed through the use of financial derivative
instruments. Xcel Energy's risk management policy allows it to manage commodity
price risk within each rate-regulated operation to the extent such exposure
exists.
Wholesale and Commodity Trading Risk - Xcel Energy Inc.'s utility subsidiaries
conduct various wholesale and commodity trading activities, including the
purchase and sale of electric capacity, energy and energy-related
instruments. Xcel Energy's risk management policy allows management to conduct
these activities within guidelines and limitations as approved by its risk
management committee, which is made up of management personnel not directly
involved in the activities governed by this policy.
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At Dec. 31, 2012, the fair values by source for net commodity trading contract
assets were as follows:
Futures / Forwards
Maturity Maturity Total Futures/
Source of Less Than Maturity Maturity Greater Than Forwards
(Thousands of Dollars) Fair Value 1 Year 1 to 3 Years 4 to 5 Years 5 Years Fair Value
NSP-Minnesota 1 $ 7,207 $ 16,207 $ 1,251 $ 1,201 $ 25,866
NSP-Minnesota 2 50 - 277 612 939
PSCo 1 474 318 - - 792
$ 7,731 $ 16,525 $ 1,528 $ 1,813 $ 27,597
Options
Maturity Maturity
Source of Less Than Maturity Maturity Greater Than Total Options
(Thousands of Dollars) Fair Value 1 Year 1 to 3 Years 4 to 5 Years 5 Years Fair Value
NSP-Minnesota 2 $ 641 $ 76 $ - $ - $ 717
1 - Prices actively quoted or based on actively quoted prices.
2 - Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of
margin-sharing mechanisms for the years ended Dec. 31, were as follows:
(Thousands of Dollars) 2012
2011
Fair value of net commodity trading contract assets
outstanding at Jan. 1
$ 20,424 $ 20,249
Contracts realized or settled during the period (12,185 ) (10,672 )
Unrealized commodity trading transactions during the period 20,075
10,847
Fair value of net commodity trading contract assets
outstanding at Dec. 31 $ 28,314 $ 20,424
At Dec. 31, 2012, a 10 percent increase in market prices for commodity trading
contracts would increase pretax income from continuing operations by
approximately $0.5 million, whereas a 10 percent decrease would decrease pretax
income from continuing operations by approximately $0.5 million. At Dec. 31,
2011, a 10 percent increase in market prices for commodity trading contracts
would increase pretax income from continuing operations by approximately $0.2
million, whereas a 10 percent decrease would decrease pretax income from
continuing operations by approximately $0.2 million.
Xcel Energy Inc.'s utility subsidiaries' wholesale and commodity trading
operations measure the outstanding risk exposure to price changes on
transactions, contracts and obligations that have been entered into, but not
closed, including transactions that are not recorded at fair value, using an
industry standard methodology known as Value at Risk (VaR). VaR expresses the
potential change in fair value on the outstanding transactions, contracts and
obligations over a particular period of time under normal market conditions. The
VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on
a consolidated basis using a Monte Carlo simulation with a 95 percent confidence
level and a one-day holding period, were as follows:
Year Ended
(Millions of Dollars) Dec. 31 VaR Limit Average High Low
2012 $ 0.45 $ 3.00 $ 0.36 $ 1.56 $ 0.06
2011 0.09 3.00 0.14 0.33 0.04
Interest Rate Risk - Xcel Energy is subject to the risk of fluctuating interest
rates in the normal course of business. Xcel Energy's risk management policy
allows interest rate risk to be managed through the use of fixed rate debt,
floating rate debt and interest rate derivatives such as swaps, caps, collars
and put or call options.
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In conjunction with the NSP-Minnesota debt issuance in August 2012,
NSP-Minnesota settled interest rate hedging instruments with a notional amount
of $225 million with cash payments of $45.0 million. In conjunction with the
PSCo debt issuance in September 2012, PSCo settled interest rate hedging
instruments with a notional amount of $250 million with cash payments of $44.7
million. These losses are classified as a component of accumulated other
comprehensive loss on the consolidated balance sheet, net of tax, and are being
reclassified to earnings over the term of the hedged interest payments. See Note
4 for further discussion of long-term borrowings.
At Dec. 31, 2012 and 2011, a 100-basis-point change in the benchmark rate on
Xcel Energy's variable rate debt would impact pretax interest expense annually
by approximately $6.0 million and $2.9 million, respectively. See Note 11 to the
consolidated financial statements for a discussion of Xcel Energy Inc. and its
subsidiaries' interest rate derivatives.
NSP-Minnesota also maintains a nuclear decommissioning fund, as required by the
NRC. The nuclear decommissioning fund is subject to interest rate risk and
equity price risk. At Dec. 31, 2012, the fund was invested in a diversified
portfolio of cash equivalents, debt securities, equity securities, and other
investments. These investments may be used only for activities related to
nuclear decommissioning. Given the purpose and legal restrictions on the use of
nuclear decommissioning fund assets, realized and unrealized gains on fund
investments over the life of the fund are deferred as an offset of
NSP-Minnesota's regulatory asset for nuclear decommissioning
costs. Consequently, any realized and unrealized gains and losses on securities
in the nuclear decommissioning fund, including any other-than-temporary
impairments, are deferred as a component of the regulatory asset for nuclear
decommissioning. Since the accounting for nuclear decommissioning recognizes
that costs are recovered through rates, fluctuations in equity prices or
interest rates do not have an impact on earnings.
Credit Risk - Xcel Energy Inc. and its subsidiaries are also exposed to credit
risk. Credit risk relates to the risk of loss resulting from counterparties'
nonperformance on their contractual obligations. Xcel Energy Inc. and its
subsidiaries maintain credit policies intended to minimize overall credit risk
and actively monitor these policies to reflect changes and scope of operations.
At Dec. 31, 2012, a 10 percent increase in commodity prices would have resulted
in a decrease in credit exposure of $11.6 million, while a decrease of 10
percent in prices would have resulted in an increase in credit exposure of $12.6
million. At Dec. 31, 2011, a 10 percent increase in commodity prices would have
resulted in a increase in credit exposure of $1.3 million, while a decrease of
10 percent in prices would have resulted in an increase in credit exposure of
$4.3 million.
Xcel Energy Inc. and its subsidiaries conduct standard credit reviews for all
counterparties. Xcel Energy employs additional credit risk control mechanisms
when appropriate, such as letters of credit, parental guarantees, standardized
master netting agreements and termination provisions that allow for offsetting
of positive and negative exposures. Credit exposure is monitored and, when
necessary, the activity with a specific counterparty is limited until credit
enhancement is provided. Distress in the financial markets could increase Xcel
Energy's credit risk.
Fair Value Measurements
Xcel Energy follows accounting and disclosure guidance on fair value
measurements that contains a hierarchy for inputs used in measuring fair value
and requires disclosure of the observability of the inputs used in these
measurements. See Note 11 to the consolidated financial statements for further
discussion of the fair value hierarchy and the amounts of assets and liabilities
measured at fair value that have been assigned to Level 3.
Commodity Derivatives - Xcel Energy continuously monitors the creditworthiness
of the counterparties to its commodity derivative contracts and assesses each
counterparty's ability to perform on the transactions set forth in the
contracts. Given this assessment and the typically short duration of these
contracts, the impact of discounting commodity derivative assets for
counterparty credit risk was not material to the fair value of commodity
derivative assets at Dec. 31, 2012. Adjustments to fair value for credit risk of
commodity trading instruments are recorded in electric revenues. Credit risk
adjustments for other commodity derivative instruments are deferred as OCI or
regulatory assets and liabilities. The classification as a regulatory asset or
liability is based on commission approved regulatory recovery mechanisms. Xcel
Energy also assesses the impact of its own credit risk when determining the fair
value of commodity derivative liabilities. The impact of discounting commodity
derivative liabilities for credit risk was immaterial to the fair value of
commodity derivative liabilities at Dec. 31, 2012.
Commodity derivative assets and liabilities assigned to Level 3 typically
consist of FTRs, as well as forwards and options that are long-term in
nature. Level 3 commodity derivative assets and liabilities represent 1.1
percent and 3.1 percent of total assets and liabilities, respectively, measured
at fair value at Dec. 31, 2012.
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Determining the fair value of FTRs requires numerous management forecasts that
vary in observability, including various forward commodity prices, retail and
wholesale demand, generation and resulting transmission system congestion. Given
the limited observability of management's forecasts for several of these inputs,
these instruments have been assigned a Level 3. Level 3 commodity derivatives
assets and liabilities included $17.5 million and $0.8 million of estimated fair
values, respectively, for FTRs held at Dec. 31, 2012.
Determining the fair value of certain commodity forwards and options can require
management to make use of subjective price and volatility forecasts which extend
to periods beyond those readily observable on active exchanges or quoted by
brokers. When less observable forward price and volatility forecasts are
significant to determining the value of commodity forwards and options, these
instruments are assigned to Level 3. There were immaterial Level 3 commodity
forwards and no Level 3 options held at Dec. 31, 2012.
Nuclear Decommissioning Fund - Nuclear decommissioning fund assets assigned to
Level 3 consist of asset-backed and mortgage-backed securities, private equity
investments and real estate investments. To the extent appropriate, observable
active market inputs are utilized to estimate the fair value of asset-backed and
mortgage-backed securities. However, less observable and subjective inputs that
may be used in conjunction with available pricing of similar securities in
active markets can be significant to these valuations. These inputs include
estimated principal prepayments and risk-based adjustments to the interest rate
used to discount expected future cash flows in a discounted cash flow
model. Given the potential significant impacts that unobservable inputs may have
on the valuations of asset-backed and mortgage-backed securities, and based on
an evaluation of NSP-Minnesota's ability to redeem private equity investments
and real estate investment funds measured at net asset value, estimated fair
values for these investments totaling $104.6 million in the nuclear
decommissioning fund at Dec. 31, 2012 (approximately 6.7 percent of total assets
measured at fair value) are assigned to Level 3. Realized and unrealized gains
and losses on nuclear decommissioning fund investments are deferred as a
regulatory asset.
Liquidity and Capital Resources
Cash Flows
(Millions of Dollars) 2012 2011 2010
Net cash provided by operating activities $ 2,005$ 2,406$ 1,894
Net cash provided by operating activities decreased by $401 million for 2012 as
compared to 2011. The decrease was the result of changes in working capital due
to the timing of payments and receipts, higher pension contributions, interest
rate swap settlements and the effect of income taxes paid in 2012 compared to a
refund received in 2011, partially offset by higher net income.
Net cash provided by operating activities increased by $512 million for 2011 as
compared to 2010. The increase was a result of higher net income, changes in
working capital due to timing of payments and the receipt of the nuclear waste
disposal settlement of $100 million. These increases were partially offset by a
$103 million increase between the periods in pension contributions.
(Millions of Dollars) 2012 2011 2010
Net cash used in investing activities $ (2,333 ) $ (2,248 ) $ (2,807 )
Net cash used in investing activities increased by $85 million for 2012 as
compared to 2011. The increase was the result of higher capital expenditures,
partially offset by the change in restricted cash due to customer refunds
associated with the nuclear waste disposal settlement with the U.S. Department
of Energy and insurance proceeds related to Sherco Unit 3 received in 2012.
Net cash used in investing activities decreased by $559 million for 2011 as
compared to 2010. The decrease was mainly due to the acquisition of generation
assets in 2010 partially offset by a change in restricted cash due to the
receipt of the $100 million nuclear waste disposal settlement.
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(Millions of Dollars) 2012 2011
2010
Net cash provided by (used in) financing activities $ 350 $ (205 ) $ 906
Net cash provided by financing activities increased by $555 million for 2012 as
compared to 2011. The increase was primarily due to higher proceeds from
short-term borrowings and the issuance of long-term debt, partially offset by
repayments of previously existing long-term debt, repurchases of common stock
and higher dividend payments.
Net cash used in financing activities increased by $1.1 billion during 2011 as
compared to 2010. The increase was primarily due to lower proceeds from the
issuance of long-term debt and common stock in 2011 and the redemption of
preferred stock during 2011.
See discussion of trends, commitments and uncertainties with the potential for
future impact on cash flow and liquidity under Capital Sources.
Capital Requirements
Xcel Energy expects to meet future financing requirements by periodically
issuing short-term debt, long-term debt, common stock, hybrid and other
securities to maintain desired capitalization ratios.
Capital Expenditures - The current estimated capital expenditure programs of
Xcel Energy Inc. and its subsidiaries for the years 2013 through 2017 are shown
in the table below. The capital expenditure forecast reflects the termination of
the Prairie Island EPU.
Actual Forecast
(Millions of Dollars) 2012 2013 2014 2015 2016 2017
By Subsidiary
NSP-Minnesota $ 1,018 $ 1,395 $ 1,135 $ 910 $ 925 $ 1,080
PSCo 887 1,075 1,000 850 800 840
SPS 389 490 400 305 300 345
NSP-Wisconsin 155 180 240 245 230 235
WYCO 1 15 - - - -
Total capital expenditures $ 2,450 $ 3,155 $ 2,775 $ 2,310 $ 2,255 $ 2,500
By Function 2012 2013 2014 2015 2016 2017
Electric generation $ 772 $ 1,025 $ 710 $ 550 $ 465 $ 570
Electric transmission 734 1,010 870 650 635 770
Electric distribution 486 515 525 525 535 545
Natural gas 247 355 365 335 325 320
Nuclear fuel 53 95 155 100 140 145
Other 158 155 150 150 155 150
Total capital expenditures $ 2,450 $ 3,155 $ 2,775 $ 2,310 $ 2,255 $ 2,500
By Project 2012 2013 2014 2015 2016 2017
Other capital expenditures $ 1,720 $ 1,710 $ 1,610 $ 1,555 $ 1,600 $ 1,755
PSCo CACJA 189 345 235 90 15 -
Other major transmission projects 179 245 260 175 320 415
CapX2020 transmission project 170 350 295 140 - -
Natural gas pipeline replacement 100 140 170 190 130 135
Nuclear fuel 53 95 155 100 140 145
Nuclear capacity increases and life extension 39 270 50 60 50 50
Total capital expenditures $ 2,450 $ 3,155 $
2,775 $ 2,310$ 2,255$ 2,500
The capital expenditure programs of Xcel Energy are subject to continuing review
and modification. Actual utility construction expenditures may vary from the
estimates due to changes in electric and natural gas projected load growth,
regulatory decisions, legislative initiatives, reserve margins, the availability
of purchased power, alternative plans for meeting long-term energy needs,
compliance with future environmental requirements, RPS, and merger, acquisition
and divestiture opportunities to support corporate strategies.
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Contractual Obligations and Other Commitments - In addition to its capital
expenditure programs, Xcel Energy has contractual obligations and other
commitments that will need to be funded in the future. The following is a
summarized table of contractual obligations and other commercial commitments at
Dec. 31, 2012. See the statements of capitalization and additional discussion in
Notes 4 and 13 to the consolidated financial statements.
Payments Due by Period
Less than 1 1 to 3 4 to 5 After 5
(Thousands of Dollars)
Total Year Years Years Years
Long-term debt, principal and interest payments (a) $ 20,342,487
$ 772,251$ 1,531,410$ 1,550,113$ 16,488,713
Capital lease obligations
378,580
18,035 35,867 32,356 292,322
Operating leases (b)(c)
2,909,139
208,494 419,339 383,957 1,897,349
Unconditional purchase obligations
12,917,688
1,996,749 3,013,183 2,206,759 5,700,997
Other long-term obligations, including current portion (d) 268,441
68,530 84,285 70,244 45,382
Payments to vendors in process 21,227 21,227 - - -
Short-term debt 602,000 602,000 - - -
Total contractual cash obligations (e) (f) (g) (h) $ 37,439,562
$ 3,687,286$ 5,084,084$ 4,243,429$ 24,424,763
(a) Includes interest payments over the terms of the debt. Interest is calculated
using the applicable interest rate at Dec. 31, 2012, and outstanding
principal for each investment with the terms ending at each instrument's
maturity.
(b) Under some leases, Xcel Energy would have to sell or purchase the property
that it leases if it chose to terminate before the scheduled lease expiration
date. Most of Xcel Energy's railcar, vehicle and equipment and aircraft
leases have these terms. At Dec. 31, 2012, the amount that Xcel Energy would
have to pay if it chose to terminate these leases was approximately $81.0
million. In addition, at the end of the equipment lease terms, each lease
must be extended, equipment purchased for the greater of the fair value or
unamortized value of equipment sold to a third party with Xcel Energy making
up any deficiency between the sales price and the unamortized value.
(c) Included in operating lease payments are $181.3 million, $367.9 million,
$344.7 million and $1.7 billion, for the less than 1 year, 1-3 years, 4-5
years and after 5 years categories, respectively, pertaining to PPAs that
were accounted for as operating leases.
(d) Other long-term obligations relate primarily to amounts associated with
technology agreements as well as uncertain tax positions.
(e) Xcel Energy Inc. and its subsidiaries have contracts providing for the
purchase and delivery of a significant portion of its current coal, nuclear
fuel and natural gas requirements. Additionally, the utility subsidiaries of
Xcel Energy Inc. have entered into agreements with utilities and other energy
suppliers for purchased power to meet system load and energy requirements,
replace generation from company-owned units under maintenance and during
outages, and meet operating reserve obligations. Certain contractual purchase
obligations are adjusted on indices. The effects of price changes are
mitigated through cost of energy adjustment mechanisms.
(f) Xcel Energy also has outstanding authority under O&M contracts to purchase up
to approximately $2.7 billion of goods and services through the year 2050, in
addition to the amounts disclosed in this table.
(g) In January 2013, contributions of $191.5 million were made across four of
Xcel Energy's pension plans. Obligations of this type are dependent on
several factors, including management discretion, and therefore, they are not
included in the table.
(h) Xcel Energy expects to contribute approximately $21.8 million to the
postretirement health care plans during 2013. Obligations of this type are
dependent on several factors, including management discretion, and therefore,
they are not included in the table.
Common Stock Dividends - Future dividend levels will be dependent on Xcel
Energy's results of operations, financial position, cash flows, reinvestment
opportunities and other factors, and will be evaluated by the Xcel Energy Inc.
Board of Directors. Xcel Energy's objective is to continue to grow earnings 5
percent to 7 percent and to grow the dividend 2 percent to 4 percent annually,
at least through 2013 or 2014. Beyond this timeframe, we anticipate that rate
base and earnings growth could be moderate. Should this occur, we anticipate
having flexibility to increase the dividend at a faster rate in the future. Xcel
Energy's dividend policy balances:
· Projected cash generation from utility operations;
· Projected capital investment in the utility businesses;
· A reasonable rate of return on shareholder investment; and
· The impact on Xcel Energy's capital structure and credit ratings.
In addition, there are certain statutory limitations that could affect dividend
levels. Federal law places certain limits on the ability of public utilities
within a holding company system to declare dividends.
Specifically, under the Federal Power Act, a public utility may not pay
dividends from any funds properly included in a capital account. The utility
subsidiaries' dividends may be limited directly or indirectly by state
regulatory commissions or bond indenture covenants.
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Xcel Energy Inc.'s Articles of Incorporation place restrictions on the amount of
common stock dividends it can pay when preferred stock is outstanding. Xcel
Energy Inc. redeemed all outstanding preferred stock in 2011. In addition, Xcel
Energy Inc.'s Junior Subordinated Indenture places restrictions on its ability
to declare and pay dividends in the event Xcel Energy Inc. defers the payment of
all or part of the current and accrued interest on its Junior Subordinated Notes
due 2068. As of Dec. 31, 2012, Xcel Energy Inc. was current on all interest
payments due on the notes.
Regulation of Derivatives - In July 2010, financial reform legislation was
passed, which provides for the regulation of derivative transactions amongst
other provisions. Provisions within the bill provide the CFTC and SEC with
expanded regulatory authority over derivative and swap transactions. Regulations
effected under this legislation could preclude or impede some types of
over-the-counter energy commodity transactions and/or require clearing through
regulated central counterparties, which could negatively impact the market for
these transactions or result in extensive margin and fee requirements.
There will be material increased reporting requirements for certain volumes of
derivative and swap activity. In April 2012, the CFTC ruled that swap dealing
activity conducted by entities under a notional limit, initially set at $8
billion with further potential reduction to $3 billion after five years, will
fall under the de minimis exemption level and will not subject an entity to
registering as a swap dealer. Xcel Energy's current and projected swap activity
is below this de minimis level. The CFTC has set an $800 million de minimis
volume exemption for swaps with "Utility Special Entities," defined by the CFTC
as primarily entities owning or operating electric or natural gas facilities
government entities, after which the entity would have to register as a swap
dealer. The bill also contains provisions that should exempt certain derivatives
end users from much of the clearing and margin requirements. Although the CFTC's
proposed rules would extend the end user exemption to margin requirements, a
requirement would be imposed to have credit support agreements in their
place. The full implications for Xcel Energy cannot yet be determined until all
the definitions and rulemakings are completed and legal reviews are conducted by
Xcel Energy. As currently proposed, Xcel Energy will be subject to reporting
requirements on April 10, 2013.
Pension Fund - Xcel Energy's pension assets are invested in a diversified
portfolio of domestic and international equity securities, short-term to
long-duration fixed income securities, and alternative investments, including,
private equity, real estate, hedge fund and commodity investments.
· In January 2013, contributions of $191.5 million were made across four of Xcel
Energy's pension plans.
· In 2012, contributions of $198.1 million were made across four of Xcel
Energy's pension plans.
· In 2011, contributions of $137.3 million were made across three of Xcel
Energy's pension plans.
· For future years, we anticipate contributions will be made as necessary.
The funded status and pension assumptions are summarized in the following
tables:
(Millions of Dollars) Dec. 31, 2012 Dec. 31, 2011
Fair value of pension assets $ 2,944 $ 2,670
Projected pension obligation (a)
3,640 3,226
Funded status $ (696 ) $ (556 )
(a) Excludes nonqualified plan of $39 million and $55 million at Dec. 31, 2012
and 2011, respectively.
Pension Assumptions 2013 2012
Discount rate 4.00 % 5.00 %
Expected long-term rate of return 6.88 7.10
Long-Term Contracts - In August 2012, PSCo entered into a 10-year physical gas
supply contract for the period between November 2013 and October 2023; this
contract will help meet a portion of the annual natural gas supply requirements
for both PSCo's electric utility and natural gas utility. The purchase price for
natural gas under the contract is indexed-based. Given current input
assumptions, the notional value of the transaction over the duration of the
contract is approximately $1.0 billion.
Capital Sources
Short-Term Funding Sources - Xcel Energy uses a number of sources to fulfill
short-term funding needs, including operating cash flow, notes payable,
commercial paper and bank lines of credit. The amount and timing of short-term
funding needs depend in large part on financing needs for construction
expenditures, working capital and dividend payments.
Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo
and SPS maintain cash operating and short-term investment accounts. At Dec. 31,
2012, approximately $5.7 million of cash was held in these accounts.
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Commercial Paper - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
each have individual commercial paper programs. The authorized levels for these
commercial paper programs are:
· $800 million for Xcel Energy Inc.;
· $700 million for PSCo;
· $500 million for NSP-Minnesota;
· $300 million for SPS; and
· $150 million for NSP-Wisconsin.
Commercial paper outstanding for Xcel Energy was as follows:
Three Months Ended
(Amounts in Millions, Except Interest Rates) Dec. 31, 2012
Borrowing limit $ 2,450
Amount outstanding at period end 602
Average amount outstanding 398
Maximum amount outstanding 602
Weighted average interest rate, computed on a
daily basis 0.36 %
Weighted average interest rate at end of period 0.36
Twelve Months Ended Twelve Months Ended Twelve Months Ended
(Amounts in Millions, Except Interest Rates)
Dec. 31, 2012 Dec. 31, 2011 Dec. 31, 2010
Borrowing limit $ 2,450 $ 2,450 $ 2,177
Amount outstanding at period end 602 219 466
Average amount outstanding 403 430 263
Maximum amount outstanding 634 824 653
Weighted average interest rate, computed on a daily basis 0.35 % 0.36 % 0.36 %
Weighted average interest rate at end of period 0.36 0.40 0.40
Credit Facilities - In July 2012, NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and
Xcel Energy Inc. entered into amended five-year credit agreements with a
syndicate of banks, replacing their previous four-year credit agreements. The
amended credit agreements have substantially the same terms and conditions as
the prior credit agreements with an improvement in pricing and an extension of
maturity from March 2015 to July 2017. The Eurodollar borrowing margins on these
lines of credit were reduced from a range of 100 to 200 basis points per year,
to a range of 87.5 to 175 basis points per year based on applicable long-term
credit ratings. The commitment fees, calculated on the unused portion of the
lines of credit, were reduced from a range of 10 to 35 basis points per year, to
a range of 7.5 to 27.5 basis points per year, also based on applicable long-term
credit ratings.
NSP-Minnesota, PSCo, SPS and Xcel Energy Inc. have the right to request an
extension of the revolving termination date for two additional one-year
periods. NSP-Wisconsin has the right to request an extension of the revolving
termination date for an additional one-year period. All extension requests are
subject to majority bank group approval.
As of Feb. 19, 2013, Xcel Energy Inc. and its utility subsidiaries had the
following committed credit facilities available to meet liquidity needs:
(Millions of Dollars) Facility (a) Drawn (b) Available Cash Liquidity
Xcel Energy Inc. $ 800.0 $ 441.0 $ 359.0 $ 0.4 $ 359.4
PSCo 700.0 4.0 696.0 1.0 697.0
NSP-Minnesota 500.0 257.2 242.8 0.6 243.4
SPS 300.0 25.0 275.0 0.2 275.2
NSP-Wisconsin 150.0 3.0 147.0 0.8 147.8
Total $ 2,450.0 $ 730.2 $ 1,719.8 $ 3.0 $ 1,722.8
(a) These credit facilities expire in July 2017.
(b) Includes outstanding commercial paper and letters of credit.
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Money Pool - Xcel Energy received FERC approval to establish a utility money
pool arrangement with the utility subsidiaries, subject to receipt of required
state regulatory approvals. The utility money pool allows for short-term
investments in and borrowings between the utility subsidiaries. Xcel Energy Inc.
may make investments in the utility subsidiaries at market-based interest rates;
however, the money pool arrangement does not allow the utility subsidiaries to
make investments in Xcel Energy Inc. The money pool balances are eliminated in
consolidation.
NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval
from their respective state regulatory commissions. NSP-Wisconsin does not
participate in the money pool.
Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize
the issuance of one billion shares of $2.50 par value common stock. As of Dec.
31, 2012 and 2011, Xcel Energy Inc. had approximately 488 million shares and 486
million shares of common stock outstanding, respectively. In addition, Xcel
Energy Inc.'s Articles of Incorporation authorize the issuance of seven million
shares of $100 par value preferred stock. Xcel Energy Inc. had no shares of
preferred stock outstanding on Dec. 31, 2012 and 2011. Xcel Energy Inc. and its
subsidiaries have the following registration statements on file with the SEC,
pursuant to which they may sell, from time to time, securities:
· Xcel Energy Inc. has an effective automatic shelf registration statement filed
in August 2012, which does not contain a limit on issuance capacity. However,
Xcel Energy Inc.'s ability to issue securities is limited by authority granted
by the Board of Directors, which currently authorizes the issuance of up to an
additional $2.0 billion of debt and common equity securities.
· NSP-Minnesota has $400 million of debt securities remaining under its
currently effective shelf registration statement, which was filed in July
2012.
· NSP-Wisconsin has $50 million of debt securities remaining under its currently
effective shelf registration statement, which was filed in July 2012.
· PSCo has an automatic shelf registration statement filed in October 2010,
which does not contain a limit on issuance capacity. However, PSCo's ability
to issue securities is limited by authority granted by its Board of Directors,
which currently authorizes the issuance of up to an additional $1.5 billion of
debt securities.
· SPS has $50 million of debt securities remaining under its currently effective
shelf registration statement, which was filed in April 2012.
Long-Term Borrowings - See the consolidated statements of capitalization and a
discussion of the long-term borrowings in Note 4 to the consolidated financial
statements.
During 2012, Xcel Energy Inc. and its utility subsidiaries completed the
following financings:
· In June 2012, SPS issued an additional $100 million of its 4.50 percent first
mortgage bonds due Aug. 15, 2041. SPS used a portion of the net proceeds from
the sale of the first mortgage bonds to repay short-term debt borrowings
incurred to fund daily operational needs. Including the $200 million of this
series previously issued in August 2011, total principal outstanding for this
series is $300 million.
· In August 2012, NSP-Minnesota issued $300 million of 10-year first mortgage
bonds with a coupon of 2.15 percent due Aug. 15, 2022, and $500 million of
30-year first mortgage bonds with a coupon of 3.40 percent due Aug. 15,
2042. NSP-Minnesota used a portion of the net proceeds from the first mortgage
bonds to repay $450 million of 8.0 percent first mortgage bonds maturing on
Aug. 28, 2012 and to redeem the following series of pollution control
bonds: $100 million of 8.50 percent bonds due Sept. 1, 2019, $27.9 million of
8.50 percent bonds due March 1, 2019 and $69 million of 8.50 percent bonds due
April 1, 2030.
· In September 2012, PSCo issued $300 million of 10-year first mortgage bonds
with a coupon of 2.25 percent due Sept. 15, 2022, and $500 million of 30-year
first mortgage bonds with a coupon of 3.60 percent due Sept. 15, 2042. PSCo
used a portion of the net proceeds from the first mortgage bonds to repay $600
million of 7.875 percent first mortgage bonds maturing on Oct. 1, 2012, and
redeemed $48.75 million of 5.10 percent bonds due Jan. 1, 2019.
· In October 2012, NSP-Wisconsin issued $100 million of 30-year first mortgage
bonds with a coupon of 3.70 percent due Oct. 1, 2042. NSP-Wisconsin used a
portion of the net proceeds from the sale of the first mortgage bonds to repay
short-term debt borrowings incurred to fund daily operational needs.
Financing Plans - Xcel Energy issues debt and equity securities to refinance
retiring maturities, reduce short-term debt, fund construction programs, infuse
equity in subsidiaries, fund asset acquisitions and for other general corporate
purposes.
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During 2013, Xcel Energy Inc. and its utility subsidiaries anticipate issuing
the following:
· NSP-Minnesota may issue approximately $400 million of first mortgage bonds in
the first half of 2013.
· PSCo may issue approximately $500 million of first mortgage bonds in the first
half of 2013.
· SPS may issue approximately $100 million of first mortgage bonds in the first
half of 2013.
Financing plans are subject to change, depending on capital expenditures,
internal cash generation, market conditions and other factors.
Credit Ratings - Access to reasonably priced capital markets is dependent in
part on credit and ratings. In 2011, Moody's placed SPS on negative outlook. On
Oct. 8, 2012, Moody's downgraded SPS by one notch, based on the expected
moderation of SPS' credit metrics due to high levels of capital expenditures and
regulatory lag. The outlook is now stable.
Off-Balance-Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those
currently disclosed, that have or are reasonably likely to have a current or
future effect on financial condition, changes in financial condition, revenues
or expenses, results of operations, liquidity, capital expenditures or capital
resources that is material to investors.
Earnings Guidance
Xcel Energy's 2013 earnings guidance is $1.85 to $1.95 per share. Key
assumptions related to 2013 earnings are detailed below:
· Constructive outcomes in all rate case and regulatory proceedings.
· Normal weather patterns are experienced for the year.
· Weather-adjusted retail electric utility sales are projected to grow
approximately 0.5 percent.
· Weather-adjusted retail firm natural gas sales are projected to decline by
approximately 1 percent.
· Rider revenue recovery for certain projects have been rolled into base rates,
therefore the change is no longer meaningful.
· O&M expenses are projected to increase approximately 4 percent to 5 percent
over 2012 levels.
· Depreciation expense is projected to increase $75 million to $85 million over
2012 levels.
· Property taxes are projected to increase approximately $35 million to $40
million over 2012 levels.
· Interest expense (net of AFUDC - debt) is projected to decrease $30 million to
$35 million from 2012 levels.
· AFUDC - equity is projected to increase approximately $15 million to $20
million over 2012 levels.
· The ETR is projected to be approximately 34 percent to 36 percent.
· Average common stock and equivalents are projected to be approximately 490
million to 500 million shares.
Item 7A - Quantitative and Qualitative Disclosures About Market Risk
See Item 7, incorporated by reference.
